The present invention relates to the processing of a petroleum production stream and more particularly relates to a method and apparatus for processing a production stream at a remote location, e.g., offshore platform, to produce stabilized liquid products having an established vapor pressure and gas products having a stabilized low dew point temperature at high pressure.
In producing petroleum from subsea deposits, it is common for the production stream to contain large quantities of gas which are commingled with the liquid products. This gas, which is comprised of lighter hydrocarbons, e.g., methane, ethane, etc., evolves out of the production stream as it undergoes temperature and/or pressure changes at the surface. Such an unstable stream of products may cause severe problems in storing and/or transporting the produced products unless the production stream is first processed to produce liquid products having a stabilized vapor pressure and gas products having a low dew point. For example, if the liquid products are to be temporarily stored at or near the production site or are to be off-loaded onto tankers, any evolving of gas after storing or loading can create severe safety hazards. Further, where either the liquid products or the gas products are to be transported by pipeline, evolving gas from liquid products or condensing liquid from gas products creates a two-phase flow condition in the pipeline which adds complexity and undesirable problems to the pumping requirements of the pipeline system. Therefore, the need for processing the production stream onsite to produce liquid products having a desired, stabilized vapor pressure and gas products with a sufficiently stabilized low dew point temperature has long been recognized.
The most severe processing requirement arise when the crude product is to be off-loaded onto tankers and the gas is to be transported by pipeline. In this case, a more highly stabilized crude product is required than in the case of pipeline shipment of crude. At the same time, substantial quantities of propane, butane, and pentane, rejected from the low dew point gas, must be carried in the crude.
Satisfactory stabilization of the crude in the face of this condition imposed by the gas demands extremely high selectivity in the distribution of these components in the two products.
Certain considerations must enter into the design of a production processing operation which is to be carried out at an offshore location which are not normally involved in land-based operation. As recognized in the article, "Process Engineering on Offshore Production Platforms" by J. H. Mitchell, THE CHEMICAL ENGINEER, June 1975, pp. 361-364, it is desirable to minimize the number of pieces of processing equipment on the offshore platform since installation techniques, space, shape, and weight limitations all impose restrictions not usually present when designing a land-based operation.
The aforesaid article provides useful insights into means for producing a stable liquid product from an offshore platform. One approach described therein is to use a minimum number of flash separators, e.g., two, which would allow acceptable production rates and still provide the required amount of gas separation from the flow stream. However, the article points out that the power requirements for gas recompression in this approach are considered excessive. Another process discussed in the article involves combining a stabilizer tower having only a few trays with two or three flash separators to improve the rejection of methane and ethane while allowing more butane and propane to remain in the liquid products. However, as recognized, stabilizer towers require substantial heating, cooling, and heat exchange equipment which go against the original goal of reducing the amount of equipment on the platform.
Still another process is proposed (see FIG. 3 in the aforesaid article) where the production stream has a relatively high pressure which is often the case with offshore production. This approach is based on using the heat from the flow stream and not precooling prior to the first flash separator stage. The flow is processed through three additional flash stages which provide a good combination of heat economy, minimum equipment, and moderate horsepower requirements in the recompression train. When dew point control of the gas is not required (as, for example, when the gas is to be directly re-injected into the reservoir), the process displayed in FIG. 3 of the aforesaid article provides an efficient means of stabilizing the liquid product.
With more severe processing conditions, however, such as are described above for simultaneous crude shipment by tanker and gas shipment by pipeline, the processes described in the aforesaid article will be unable to meet both product specifications without either an excessive requirement for gas compression horsepower or the withdrawal of a third product from the platform. This third product derives from the light condensate which is removed from the gas in the dew point control section (e.g., by propane refrigeration).
The disposal of this third product stream presents a real and difficult problem in offshore operations since in known environments where this process would find application, the compositions of the inlet stream are such that the third product stream will normally be too light to add to the crude products and too heavy to efficiently burn as fuel. The methane/ethane/propane content of the third product stream will be so high that if it is "spiked back into the crude product" as suggested by the article, the resulting spiked crude will have a vapor pressure far in excess of what can presently be considered "stable" for shipment by tanker. One possible solution for this problem is to divert this third product stream to a stabilizing tower with the stabilized bottoms "spiked back into the crude product." Since the off-gas from the stabilizer must be recycled through the process, however, total compressor horsepower requirements would be increased to unrealistic levels. The compressor horsepower can be reduced only by withdrawal of at least a portion of the condensate from the process, most likely as a liquid from the stabilizer overhead.
Further, in a process such as shown in FIG. 3 of the article, there are no means for maintaining the final vapor pressure of the crude product at a substantially constant value when changes in composition, temperature, and/or pressure of the inlet stream occur. Since for known inlet streams, the pressure in the last stage of separation of the process will have to be quite close to ambient pressure to achieve desired crude stability, reduction in the last stage pressure as a means for controlling the vapor pressure is not considered practical. This will not normally be a problem when the only objective of the process is stabilization of the liquid product. When a low dew point gas is also required, however, the resulting increase in light components in the crude will cause the process to operate much closer to the vapor pressure limit acceptable for tanker shipment. Without adequate control, successful operation of the process in the face of expected variations from design conditions would be seriously impaired.
As can be seen from the above discussion, a process such as is shown in FIG. 3 of the above-mentioned article will not provide a satisfactory means of producing both a stable liquid product and a low dew point gas product. It would require substantial additional processing equipment for condensate stabilization, it would require the withdrawal of an unwanted third product from the platform, and it would be unable to achieve adequate control of the vapor pressure of the liquid product.